The field of hydrocarbon production is directed to retrieving hydrocarbons that are trapped in subsurface reservoirs. Typically, these reservoirs are comprised of parallel layers of rock and fluid material each characterized by different sedimentological and fluid properties. Hydrocarbons accumulate below or between non-porous or lower permeability rock layers, forming reservoirs. These hydrocarbons can be recovered by drilling wells into the reservoirs. Accordingly, hydrocarbons are able to flow from the reservoirs into the well and up to the surface. The production rate at which hydrocarbons flow into the well is vital to the petroleum industry and as a result, a large amount of effort has been dedicated to developing reservoir simulation techniques in order to better predict fluid flow characteristics within subsurface reservoirs.
Highly complex geological subsurface reservoirs, such as reservoirs having a network of fractures, present unique and specialized challenges with regards to forecasting fluid flow characteristics. As discussed later in more detail herein, these challenges arise due to characterization, gridding, discretization, and simulation of the network of fractures within a reservoir.
Subsurface reservoirs with a network of fractures typically have a low permeability rock matrix, making it difficult for hydrocarbons to pass through the formation. Fractures can be described as open cracks or voids within the formation and can either be naturally occurring or artificially generated from a wellbore. The presence of fractures can therefore, play an important role in allowing fluids to flow through the formation to reach a well. For example, hydrocarbon production rates from a well tend to be very different depending on whether the well is intersected by a large fracture. Sometimes fluids such as water, chemicals, gas, or a combination thereof, are injected into the reservoir to help increase hydrocarbon flow to the production well. In situations in which a fracture provides for direct connectivity between a production well and a fluid injection well, the injected fluids can flow through the fracture and bypass the majority of hydrocarbons within the formation that the injected fluids were supposed to help produce.
The positioning of wells in a fractured reservoir becomes increasingly important as wells can be drilled into highly fractured areas to maximize the production rate. Thus, it is desirable to characterize the extent and orientation of fractures in hydrocarbon reservoirs to optimize the location of wells and properly forecast fluid flow characteristics through the subsurface formation. However, realistic geological characterizations of the reservoir are generally too computationally expensive for direct flow simulation of full-field simulation models because current reservoir simulators are encumbered by the level of detail contained in realistic geological characterizations. In particular, these simulations are hindered due to the presence of large models and the high contrast in matrix and fracture permeabilities. This can further be compounded by multiphase flow (oil, gas, solvent, and water), the need to use hydrocarbon pseudo phases to represent first-contact miscible fluids (oil and solvent), the inclusion of complex physics to compensate for gravity and capillarity effects on fluid flow, and complicated producing rules based on actual field development plans.
Various techniques related to the field of reservoir simulation have been explored in efforts to make the simulation of fluid flow within a fractured subsurface reservoir computationally-efficient. These techniques include characterization approaches, gridding techniques, discretization schemes, and simulation methods including upscaling. However, while these attempts may allow for a reduced computational time, they typically are based off of simplifying assumptions that result in less reliable forecasts of the fluid flow characteristics.